Monday, January 20, 2020

Drilling and Completions Through Salt

Properties of salt- pseudoplastic flow under subsurface temperatures and pressures, and low permeability - that make salt bodies effective hydrocarbon traps also present unique challenges for oil and gas operators.



 Special considerations, from selecting drilling fluids and bits to implementing casing programs and cementing procedures, are required to produce long-lasting wells. Methods developed on the US Gulf Coast and in the Gulf of Suez, Egypt have improved the efficiency and reliability of drilling and completion operations in thick salt sections. 

Unlike typical sediment sequences in which horizontal stresses are less than vertical stresses from overburden, salt is like a fluid, with stresses in all directions approximately equal to the overburden. Therefore, if borehole fluid pressure is less than in-situ salt strength, stress relaxation may significantly reduce openhole diameters. In some cases, relaxation and salt creep can cause borehole restrictions even before drilling and completion operations are finished. Undergauges boreholes can lead to stuck drillpipe, problems running casing and ultimately casing failures- ovaling, bending or collapse. 

To maintain near-gauge boreholes, drilling fluids must minimize hole closure and washouts. Water - and oil-base muds with saturated and undersaturated salt concentrations, and synthetic fluids have been used to drill salt, but no single system works all the time. Water-base muds with low salt concentrations try to balance salt erosion and dissolution with creep rate to maintain hole size. However, because salt creep and dissolution change across thick salt sections, this can be problematic and hole size may vary with depth.






Sunday, January 19, 2020

Exploring the Subsalt

Advances in seismic imaging have changed the way explorationists view salt bodies. Once seen as impenetrable barriers to geophysical probing with some flanking pay zones, many salt structures are now proving to be thin blankets shielding rich reserves.

 From the earliest days of exploration, prospectors associated salt with oil and gas - but not always for the right reasons. In the 1920s, so many successful wells were drilled around salt domes that logging methods were tuned to identify the high-salinity water in formations overlying pay zones. By 1923, gravity and seismic methods became successful in spotting salt domes, and the industry was on its way to understanding the structural role played by salt. Today, interpreters can view and tour salt structures with the help of powerful graphics workstations. 

Salt is one of the most effective agents in nature for trapping oil and gas: as a ductile material, it can move and deform surrounding sediments, creating traps; salt is also impermeable to hydrocarbons and acts as a seal. Most of the hydrocarbons in North America are trapped in salt-related structures, as are significant amounts in other oil provinces around the world. Many reservoirs in the North Sea are below salt, as are large fields in the Gulf of Suez.

A product of seawater evaporation, salt accumulation can reach thusands of feet in thickness. Salt retains a low density of 2.1 g/cm3 even after burial. However, the surrounding sediments compact and at some depth become denser than the salt - an unstable situation. If the overlying sediments offer little resistance, as is sometimes the case in the gulf of Mexico, the salt rises, creating characteristic domes, pillows and wedges that truncate upturned sedimentary layers. If the overburden does resist, salt can still push through, creating faults in the process. If tectonic conditions are right, extensional faulting in the rigid overburden can open the way for salt ascent. Much of the Zechstein salt pervasive in the North Sea has been mobilized this way.

In contrast to salt's low density is its high seismic wave velocity - 4400 m/sec (14,432 ft/sec) - often more than twice that of surrounding sediments. The strong velocity contrast at the sediment-salt interface acts like an irregularly shaped lens, refracting and reflecting seismic energy.


Early data processing techniques treated this contrast like a mirror, resulting in images that portrayed salt features as bottomless diapirs extending to the deepest level of seismic data. In the 1980s, seismic processing began to correctly image the steeply dipping and sometimes overhanging faces of salt where hydrocarbons could accumulate.



In the last five years, a new image of salt has emerged. In some areas not only is the top of salt cleary visible, but the bottom also. Geologists hypothesize that in these areas of allotchnous salt - found away from its original depositional position- conditions allow the salt, having reached vertical equilibrium, to begin flowing horizontally. 



In the Gulf of Mexico, this occurs mainly in deep water beyond the continental shelf, where sediment cover is not as thick as it is near shore. Wells drilled through thin salt sheets have encountered oil-bearing sediments below.


However, knowledge of the existence of hydrocarbons below salt is insufficient reason to start drilling. Drilling salt is risky. The salt itself is weak and undergoes continuous deformation. Below intruded salt, sediment layers are often disrupted and overpressured. And most important, unless seismic data have been processed to image through the salt, the position of target is unknown. 

A few operators have announced significant oil discoveries beneath salt in the Gulf of Mexico, rekindling a spirit of exploration in the Gulf. Phillips Petroleum Company, in partnership with Anadarko Petroleum Corporation and Amoco Production Company, announced the first commercial Gulf of Mexico subsalt discovery with the Mahogany prospect in 1993, and attributed the success to the imaging technique called prestack depth migration. 

Drilled in 375 ft [114 m] of water to a depth of 16,500 ft [5030 m] , the well produces from sediment layers beneath a salt sheet 3000 to 8000 ft thick.

Since the Mahogany find, many more wells have been drilled in the area, with other operators experiencing similar success. Before prestack depth migration, the success ratio in the subsalt play was around 5%. The new technique is increasing that to 25%. Depth migration is also bringing first-time details to light in some of the many North Sea reservoirs that produce from below salt, and operators plan exploration campaigns in the Red Sea using the same method.

What is this imaging technique and how does it help illuminate subsalt reservoirs? The answers are found in a review of the family of imaging methods, including prestack depth migration, that are bringing subsalt and other complex structures to light.

Imaging

Imaging describes the two seismic data processing steps, stacking and migration, that bring seismic reflections into focus. Stacking attempts to increase signal-to-noise ratio by summing records obtained from several seismic shots reflecting at the same point. Energy arrives on each trace at a different time, depending on the source-receiver separation, or offset. 










Monday, January 6, 2020

Advanced Fracturing Fluids Improve Well Economics

The oil and gas industry has witnessed a revolution in fluids technology for hydraulic fracturing. Starting in the mid 1980s, focused research led to major improvements in the performance of well stimulation fluids. Today, new additives and fluids are extending these capabilities and providing innovative solutions to nagging problems. The results are more efficient and cost-effective treatments for enhancing well production. 

Hydraulic fracturing is one of the oil and gas industry's most complex operations. This technique has been applied worldwide to increase well productivity for nearly 50 years. Fluids are pumped into a well at pressures and flow rates high enough to split the rock and create two opposing cracks extending up to 1000 ft [305 m] or more from either side of the borehole. Sand or ceramic particulates, called proppant, are carried by the fluid to pack the fracture, keeping it open once pumping stops and pressure decline. 

What defines a successful fracture? It is one that : 
  • is created reliably and cost-effective
  • provides maximum productivity enhancement
  • is conductive and stable over time.

This article describes today's fracturing operations and the pivotal role played by the fracturing fluid. Then, it highlights four new fluid technologies that are improving fracture success and well economics. 

The Rock, the Mechanics and the Fluid

Historically,  fracturing has been applied primarily to low-permeability - 0.1 to 10 md - formations with the goal of producing narrow, conductive flow paths that penetrate deep into the reservoir. These less restrictive linear conduits replace radial flow regimes and yield a several-fold production increase. For large-scale treatments, as many as 40 pieces of specialized equipment, with a crew of 50 or more, are  required to mix, blend and pump the fluid at more than 50 barrels per minute (bbl/min).

Until recently, treatments were performed almost exclusively on poor producing wells (often to make them economically viable). In the early 1990s, industry focus shifted to good producers and wells with potential for greater financial return. This, in turn, meant an increased emphasis on stimulating high-permeability formations.

The major constraint on production from such such reservoirs is formation damage, frequently remedied by matrix acidizing treatments. But acidizing has limitations, and fracturing has found an important niche. The objective in highly permeable formations is to create short, wide fractures to reach beyond the damage. This is often accomplished by having the proppant bridge, or screen out, at the end, or tip, of the fracture early in the treatment. This "tip screenout" technique is the opposite of what is desired in low-permeability formations where the tip is ideally the last area to be packed.




 Why the different approach? The answer is found in the relationship between fracture length and the permeability contrast between the fracture and the formation. Where the contrast is large, as for low-permeability reservoirs, longer fractures provide proportionally greater productivity. Where the contrast is small, as in high-permeability formations, greater fracture length provides minimal improvement. Fracture conductivity is, however, directly related to fracture width. Using short- about 100 ft- and wide fractures can prove beneficial. 

High-permeability formation treatments are on a far reduced scale. Only a few pieces of blending and pumping equipment are required, and pumping times are typically less than one hour, and often only 15 minutes. Fluid is pumped at 15 to 20 bbl/min with a total volume of 10,000 to 20,000 gal and total proppant weight of about 100,000 lbm. This technique has been successful in the North Sea, Middle East, Indonesia, Canada and Alaska, USA.

While fracturing treatments vary widely in scale, each requires the successful integration of many disciplines and technologies, regardless of reservoir type. Rock mechanics experiments on cores, specialized injection testing and well logs provide data on formation properties. Sophisticated computer software uses these data, along with fluid and well parameters, to simulate fracture initiation and propagation. These results and economic criteria define the optimum treatment design. Process-controlled mixing, blending and high-pressure pumping units execute the treatment. Monitoring and recording devices ensure fluid quality and provide  permanent logs of job results. Engineers tracking the progress of the treatment use graphic displays that plot actual pumping parameters against design values to facilitate real-time decision making. Production simulators compare treatment results with expectations, providing valuable feedback for design of the next job. 

At the heart of this complex process is the fracturing fluid. The fluid, usually water-based, is thickened with high molecular weight polymers, such as guar or hydroxypropyl guar. It must be chemically stable and sufficiently viscous to suspend the propant while it is sheared and heated in surface equipment, well tubulars, perforations and the fracture. Otherwise, premature setling of the proppant occurs, jeopardizing the treatment. A suite of specially designed chemical additives imparts important properties to the fluid. Crosslinkers join polymer chains for greater thickening, fluid-loss agents reduce the rate of filtration into the formation and breakers act to degrade the polymer for removal before the well is placed on production.


 The fracture is created by pumping a series of fluid and proppant stages. The first stage, or pad, initiates and propagates the fracture but does not contain proppant. Subsequent stages include proppant in increasing concentrations to extend the fracture and ensure its adequate packing.

Fracturing fluid technology has also developed in stages. Early work focused on identifying which polymers worked best and what concentrations gave adequate proppant transport. Then, research on additives to fine-tune fluid properties hit high gear. 

Much was learned, but what finally emerged was a huge array of complicated fluids - difficult to prepare and pump - and an amazing assortment of single-use additives ( most had to be custom manufactured) that required expensive material inventories. 

In the past ten years, a more productive research direction has emerged. Oil companies, service companies and polymer manufacturers have concentrated on the basic physical and chemical mechanisms underlying the behaviour of fracturing fluids in an attempt to find improved approaches to fluid design and use. This initiative has led to major advances, including higher-performing polymers, simpler fluids, multifunctional additives and continuous, instead of batch, mixing. These developments have had a significant, beneficial impact on the industry.


  • controlling fluid loss to increase fluid efficiency
  • extending breaker technology to improve fracture conductivity
  • reducing polymer concentration to improve fracture conductivity
  • eliminating proppant flowback to stabilize fractures

Each provides new opportunities for improving well economics, as described in the remainder of this article. 


Controlling Fluid Loss


A portion of the fluid pumped during a fracturing treatment filters into the surrounding permeable rock matrix. This process, referred to as fluid leakoff or fluid loss, occurs at the fracture face. The volume of fluid lost does not contribute to extending or widening the fracture. Fluid efficiency is one parameter describing the fluid's ability to create the fracture. As leakoff increases, efficiency decreases. Excessive fluid loss can jeopardize the treament, increase pumping costs and decrease post-treatment well performance. Typically, particulates or other fluid additives are used to reduce leakoff by forming a filter cake - termed an external cake - on the surface of the fracture face. 

Acting together with the polymer chains, the fluid loss material blocks the pore throats, effetively preventing invasion into the rock matrix. This approach has been applied succssfully for decades to low-permeability (< 0.1 md) formations in which polymer and particulate sizes exceed those of the pore throat. In high-permeability reservoirs, however, fluid constituents may penetrate into the matrix, forming a damaging internal filter cake.This behavior has prompted mechanistic studies to determine the impact on fracturing treatment performance.

Classic fluid-loss theory assumes a two-stage, static -or nonflowing-process. As the fracture propagates and fresh formation surfaces are exposed, an initial loss of fluid, called spurt, occurs until an external filter cake is deposited. Once spurt ceases, pressure drop through the filter cake controls further leakoff. For years, researchers have developed fluid-loss control additives under nonflowing conditions based on this theory.

The conventional assumptions, however, neglect critical factors found under actual dynamic -or flowing - conditions present during fracturing, including the effects of shear stress on both external and internal filter cakes and how fluid-loss additives move toward the fracture face. In high-permeability formations, with an internal filter cake present, most of the resistance to leakoff occurs inside the rock, leaving the external cake subject to erosion by the fluid.

Analysis of fluid loss under dynamic conditions relates external cake thickness to the yield stress of the cake at the fluid interface and the shear stress exerted on the cake by the fluid. These, in turn depend on the physical properties of the cake and the rheological properties of, and shear rate induced in, the fluid. Whether an external filter cake forms, grows, remains stable or erodes depends on the way these parameters vary and interact over time and spatial orientation. 

Similarly, the effectiveness of additives to control fluid loss depends on two factors: their ability to reach the fracture face quickly and their ability to remain there. The former is governed by the drag force exerted on the particles and the latter by the shear force exerted on them. The larger the ratio of drag to shear, the greater the chance that the particles will remain on the surface. A greater leakoff flux to the wall, smaller particle dimensions and a lower shear rate flavor sticking. Promoting higher leakoff for better additive placement seems directly at odds with controlling fluid loss! However, in practice, higher initial leakoff can yield greater overal fluid efficiency.

To confirm the controlling mechanisms, dynamic fluid-loss tests were conducted using a slot-flow geometry , determined to be the simplest representation of what occurs in a fracture. To completely describe the process, computer-controlled equipment was constructed to prepare and test fluids under dynamic conditions, subjecting them to the temperature and shear histories found in a fracture. 

Cores of various lengths were used in the tests to simulate a fracture segment at a fixed distance from the wellbore. As the fracture tip passes a spesific point, spurt occurs and the shear rate reaches a maximum. Then, as the fracture widens, the shear stress decreases.

Laboratory tests show that, for comparable fluids and rocks with permeabilities of up to 50 md, fluid loss is greater than under dynamic conditions than static conditions. Further, examining the impact of shear stress and permeability on the magnitude of fluid loss and the effectiveness of leakoff control additives in high-permeability formations led to five key conclusions.


  1. High shear rates can prevent the formation of an external filter cake and result in higher than expected spurt. 
  2. An internal filter cake controls fluid loss, especially near the fracture tip. 
  3. The effectiveness of fluid-loss additives increases with formation permeability and decreases with shear rate and fluid viscosity.
  4. Reducing fluid loss means reducing spurt, particularly under high shear conditions and in high-permeability formations.
  5. At high shear rates with no external filter cake, efficient spurt control must be achieved by plugging the pore throats at the surface of the rock.



The effects of shear depends on the type of fluid and the formation permeability. Typically, above a threshold shear level, no external filter cake is formed. The magnitude of fluid loss is dependent on the type of polymer and whether it is crosslinked. If the permeability is high enough and the fluid structure degrades with shear, polymer may be able to penetrate the rock matrix. 









































Friday, January 3, 2020

Getting the Most from Perfs

To minimize entrance effects and maximize fracture conductivity, Kniffin and a team of Texico engineeres are trying a combination of five techniques: 

  • Larger-diameter perforations. Historically, holes were commonly of small diameter- typically 0.35 in. or smaller. Larger-diameter perforations - 0.5-in and larger are thought to result in a more direct path from perf to fracture. 
  •  Tighter phasing of perforations. Decreasing the phase angle of perforations maximizes the likelihood of a perforation aligning parallel to the fracture plane. At the ideal alignment, fractures tend not to split into multiple branches, minimizing the number of restrictions that lead to screenout.
  • Proppant slugging. This process involves early pumping of small, intermittent volumes of proppant slurry (slugs) with progressively higher densities of proppant. These slugs are thought to plug off minor fractures, diverting more of the proppant to the major fractures, improving their conductivity.  
  •  Maximized pad fluid viscosity. A pad is the first fluid pumped during hydraulic fracturing, and generally does not contain proppant. The more viscous the fluid, the wider the fracture; it also makes the job more costly because of the requirement for added horsepower and for breakers, chemicals that reduce viscosity after pumping. Optimal viscosity balances added cost against higher fracture conductivity. 
  • Limiting the height of the perforated intereval, called point-source perforating. Perforating only limited height, usually in the middle of the interval interest, reduces the number of multiple fractures and increases the likelihood of them coalescing into fewer, larger fractures.

Thursday, December 26, 2019

Texaco : Fracs in the Permian Basin

More than one third of the hydrocarbons produced in the United States since the 1920s has come from the 75,100 km square area of West Texas and southeast New Mexico called the Permian Basin. The region has yielded 30 billion of the 87 billion barrels of oil produced in the United States in 70 years. Production today (1995) is 38,000 barrels of oil equivalent (BOE) per day, and although it is declining slowly, it is still the most prolific area outside of Alaska. Proved reserves are 5.4 billion BOE.

The Permian Basin is a hodgepodge of depositional environments, including reefs and shelf carbonates, turbidites, beach and nearshore sands and sabkha. Well productivity is 20 to 100 BOPD, with the typical well making 35 BOPD. Texico conducts one of the most active drilling programs in the  basin, and operates some 15,000 wells. Following the diversity of depositional environments, well depths vary from 3500 to 28,000 ft [1066 to 8534 m]. About half of Texico's production is from carbonates, and the bulk of work for DESC engineer Goofy centers on fracturing tight dolomite oil and gas reservoirs.

Fracturing is big business for Texico in the Permian Basin. In 1994, the company fraced 200 wells- with up to three fracs per well - and if the pace of drilling holds, the number may rise to 250 this year. With one well fraced every two days, Goofy monitors the progress of about 30 wells at one time.

Along with fracture design, Goofy also has been coordinating evaluation of methods to find the optimal fracturing program. For this challenging area, what works in one well, may fail in another well that appears to have identical properties. 

The main challenge is avoiding near-well-bore screenout: bridging of proppant in the fracture near the wellbore, which halts fluid entry and propagation of the fracture. Wellbore screenouts can occur in the complex connection between the wellbore and fracture entrance. This complexity, called tortuosity, generally results from too large an angle between the perforation and the plane of the natural fracture, or from multiple fractures that may or may not coalesce into a preferred single fracture. Coalescing of fractures is likely to produce tortuosity when perforations are not aligned with the principal stress in the formation. Multiple fractures produce narrower fracture channels and more surface area for fluid loss through the fracture faces. Both coalescing and multiple fracs increase the likelihood of proppant accumulation near the wellbore and a resulting screenout. Reducing fracture entrance effects is required for proppant to flow unimpeded, and for the fracture to reach maximum length and conductivity. 


Goofy works with Texico engineers to determine optimum fracture dimensions and develop a treatment pumping schedule, contributing to Texico'sa saving at least one engineering day per frac design. He tracks the performance of treaments to discern patterns that lead to success or failure. This is a critical step, since process improvement is integral to the success of the alliance.


 Coalesce of fracture as a cause of tortuosity. How fractures evolve from perforations can contribute to pressure drop, and proppant bridging, in the region near the wellbore. As fractures propagate, they may form an overlapping arragement, called en echelon, and eventually connect. Isolated rhomboids of rock develop between the connecting tails of the fractures. Small fractures associated with these rhomboids are suspected to contribute to the pressure drop that leads to early bridging of proppant. Limiting the height of the fractured intereval is thought to reduce the number of rhomboids, and thus the mechanism that leads to bridging.

With up to four jobs per week, Goofy can't attend each one. For critical jobs, he relies on a double cellular phone connection between his office in Denver and the dowel crew at the wellsite in West Texas. One line provides a voice connection. The other furnishes real-time, on-screen monitoring of up to 10 variables during the job, typically including pump rate, surface pressure, fluid density and additive composition and concentrations.

An example of a paradigm break was in Texico's design of Permian Basin completions. Texico practice was to complete wells using three strings of casings: surface, intermediate and production string. This approach was perceived to minimize risk of loss of well control from lost circulation or water entry. 

Texico engineers looked for a new method and worked with Goofy to design lightweight cementing techniques that allowed elimination of the intermediate string. Lighter fluids permitted cementing the production string in one stage or, if very long, in two stages.

Taking this approach required that Texico accept the risk of lost circulation and water entry during drilling. Managing this risk, however, or even repairing damage done by water entry, is less costly that setting intermediate casing. Texico has used the procedure on select projects since 1992, saving 10 to 15% on each well. 

"It allows us to drill in places where we could not have afforded to drill otherwise, " said Phil Basham. "Every nickel saved got reinvested in a new well. That's the kind of benefit we're after."




Shell Western E&P: High-Pressure Coiled Tubing

South Texas presents Shell Western E&P Inc. with some of the company's most challenging gas wells. They are deep, hot, geopressured and sometimes sour. In the Rio Grande Valley, Shell produces 450 million cubic ft of gas and condensate per day from about 350 wells.  The main technical challenge is beating the decline curve of the wells - the fall in productivity over time - by lowering the cost of production and producing hydrocarbons as fast as possible.

Duncan Newlands, Shell's Houston based DESC engineer, addresses this challenge by splitting his time between fracture work and coiled tubing services. His contribution to fracture design have increased dowel's share of jobs and enhanced efficiency for dowel productivity for Shell. His contribution to an innovative application of coiled tubing for workovers helped save Shell $1 million in 1994 and expanded dowel's coiled tubing services in the region.

Coiled tubing is used to clean out sand plugs inserted during multistage massive hydraulic fracturing. In this fracturing technique, the bottom zone is fractured first, then the interval is filled with sand to isolate it, and the zone above is fractured. The second zone is then filled with sand, and the zone above that is treated, and so on up the hole. After the final fracture, the column of sand, which may reach a thickness greater than 1000 ft , must be removed to commingle production from all the zones. 

With wellhead pressures sometimes approaching 10,000 psi, snubbing units were used to remove sand, since conventional coiled tubing units can accomodate wellhead pressure only up to 3500 psi. A snubbing unit is a combination of pressure control and pipe handling equipment. The equipment jacks pipe through the pressure control equipment 30 ft at a time. When at the required depth, gel is pumped down the pipe to circulate sand to the surface. The typical south Texas well has a producing interval of at least 200 ft , at a depth of 12,000 ft [3658 m]. Because only 30 ft can be "snubbed" at a time, removal of the column of sand can take 7 to 12 days. 

A team of Shell and dowel engineers investigated the practicality of adapting existing coiled tubing and surface equipment to cope with the high pressures. They found that conventionally available 1 1/4-inch, thick-walled coiled tubing provided the best of all possible properties: strong enough to safely endure the wellhead and downhole pressures, large enough to accomodate pump rates for efficient cleanout, and having an acceptable fatigue life, given the high operating pressure. 

Two pieces of equipment had to be adapted. First, the high pressure at the wellhead made buckling of tubing at the stripper a concern. To combat this, an antibuckling guide was utilized to provide lateral support and minimize the distance between the stripper and chains that drive the tubing in and out of the injector. Second, a 15,000-psi blowout preventer and stripper were built to improve the economics, safety and speed of  the coiled tubing job. Yard tests at operating pressures showed the new equipment could perform several cleanouts before a string of coiled tubing would have to be retired to conventional work. 


































Sunday, December 22, 2019

Consultant Engineer Work

Goofy arrives at the Texico office in Denver at 7:00 in the morning, wearing a texico windbreaker with" Star-Quality Ambassador" embossed on the front. The jacket is a point of pride: he's part of a team recognized for saving the company $38 million in drilling costs in the last two years.

Goofy sheds the jacket, grabs a notepad and heads to the morning meeting. He joins a half-dozen drilling engineers seated around a teleconference phone discussing the previous day's well reports with texico operations groups in Midland, Texas, USA and other locations. The teams discuss good news and bad, and debate solutions. When the agenda turns to hydraulic fracturing in Wes Texas, all eyes land on Goofy.

On a typical day like this, follow Goofy around and you might conclude he's a hard-working Texico engineer. There is little obvious evidence that he's a Dowel engineer, one of 95 assigned to client offices in North America. By the end of 1995, an estimated 175 engineers worldwide will be assigned to customer offices in the DESC program, short for Design and Evaluation Services for Clients.

For both Dowel and operating companies like Texico, the DESC program provides significant benefits. DESC engineers are dedicated to serving a single customer, cutting cost, improving quality and raising productivity. They contribute years of experience in completion engineering, and when they are practically self-sufficient, bringing their own networked workstation, a bookshelf of dowel software and a modem. The oil company provides an office with a desk and chair, phone and electricity, and access to well fiels and company experts.

The oil company gets a seasoned engineer with a fresh perspective. Dowel gets a richer understanding of client needs and improved access to opportunities for well treatment services. Both parties benefit from daily contact that build trust, which stimulates the cross-pollination of ideas. This candid exchange results in easier acceptance of new ideas and faster development of solutions. As management consultants say, it's a win-win scenario.

Breaking Workplace Barriers

Given the sometimes adversarial relationships that formerly existed between service and operating companies, placing a contractor in an oil company office may seem like an unusual move. 

In the programs, the relationship between contractor and operator did not change. Where you worked changed, but not usually how you worked. The contractor mainly operated a system for the client and fulfilled client requests on a per-bid basis. Placement of the engineer and equipment in the oil company office was for expediancy and took place within the constraints of a conventional contractual relationship.

For the DESC engineers, candidate recognition was not the sole activity. The first opportunities were improving the logistics of well treatment. This involved collaborating with the drilling or production departement to better coordinate Dowel crews, equipment and delivery of raw materials. Small improvements in logistics yielded large gains in productivity.

For example, better scheduling can allow a crew to perform two jobs per day instead of one, or can take advantage of a crew that is 20 miles from the well instead of 200 miles. Early in the DESC program, it became clear that simply having a DESC engineer in house significantly improved logistics to the benefit of both dowel and its clients.

Until about 1992, logistics remained a key activity for the handful of DESC engineers. By the end of 1992, the focus shifted to emphasize candidate recognition, which today remains the core of the program. This umbrella covers the range of pumping and fluids engineering services, including fracturing, sand control, coiled tubing services, acidizing, drilling fluids and cementing. In 1995, as Sch** wireline & Testing engineers are being located in client offices along with dowel engineers, the umbrella now includes log input to completion services. Candidate recognition is expected to grow in importance in mature markets, as operators seek to extend the life of aging fields.

With candidate recognition as the focus, a new contractor-operator relationship had been cemented. "In the old way of working," said Dundun Newland, a DESC engineeer for Shell Western E&P in Houston, " the client might say, 'Here's my pump schedule. Be ready to roll Tuesday morning at 5.' Now the client might say, 'Work with our team to develop a completion plan for this well that gives both companies the highest value. 'Oil companies are beginning to realize there's benefit in trusting us to meet or exceed their criteria for job performance."  

Given the large scope of responsibilities the DESC program places on dowel engineers, training had to rise to the challenge. The DESC program starts with engineers who have mastered the basics. Those picked for the program typically have had at least three years of experience in completion and fluids engineering and have demonstrated both enterpreneurial spirit and interpersonal skills. These skills are essential, since the job requires technical proficiency, business acumen and diplomacy. When first installed in the client office, the engineer must win the confidence of oil company colleagues and, to be most effective, must progress from being regarded as a guest to being accepted as one of the team. Foremost, the engineer must be able to work within the oil company culture to develop support for optimal solutions. 

To build the range of needed skills, most new DESC engineers receive three to six months of training in the Production Enhancement Group (PEG) in Houston. The PEG comprises specialists from Wireline & Testing, dowel & anadrill, who identify wells with potential for increased production and develop an integrated program to raise well productivity. Client interest in PEG projects is funneled through Schlumberger sales engineers throughout North America. PEG engineers then review client well files and submit bids for well treatment based on the analysis.

In the PEG program, dowel engineers learn the essentials of well performance simulation and candidate recognition. This includes development of proficiency with NODL production system analysis and other dowel software used in candidate recognition. It also includes training in perforation, pressure transient and decline curve analysis, fracture theory and fracture fluids engineering.

The engineer then is posted to an oil company, usually in the production or drilling department, and begins gradual assimilation.  






















Friday, December 20, 2019

Integration in Well Testing Services

One of the most comprehensive packaging of tasks is seen in well testing. Services ranging from perforating to running tubulars, from production logging to subsurface data acquisition could be performed by many individuals from separate service companies. In a typical example, these tasks- if performed separtely- require 22 people. Integration reduces this number to 15.





  

     Consider two spesific tasks- tubing conveyed perforating (TCP) and drillstem testing (DST). A typical TCP job requires two people to prepare and hook up a length of TCP guns - usually with help from the rig crew. Similarly, running a DST string also requires two operators. Often TCP guns are run below the DST string. If separate companies are involved, then four people are required. A service company providing both sets of equipment and a crew trained to handle both operations can reduce this number to two.

Once this streamlined crew has rigged up the TCP guns, they rig up the DST string. For the oil company, having one service company perform both tasks has three advantages. First, the crew knows how to set up and operate both sets of equipment, so that they won't interfere with each other - vital in an operation dealing with explosives and high pressure. Second, there is a reduction in personnel on board, saving costs on transportation, accomodation and insurance. Third, there is a single company to deal with, easing communication and simplifying logistics.

Similarly, well testing crews are trained to handle several services; when they are not working on one tasks they can be assigned to another.

Coordinating groups of services is the simplest form of integrated services and is not new to the service industry. Sch** wireline &  Testing has run combined DST and TCP services since the early 1980s. And, to ensure compatibility, DST and TCP product development is performed at a single location in Rosharon, Texas, USA.

Integration of services has also led to design standardization in other areas of well testing. Production logging tool strings now incorporate sophisticated pressure gauges, allowing pressure transient analysis during production logging runs. The latest gauge systems may be mounted on different conveying systems that allow better utilization and greater flexibility in well test design.